Management's Discussion and Analysis for the second quarter ended June 30, 2017

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world's largest petroleum resource basins – Canada's Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and natural gas in Canada and internationally; we transport and refine crude oil, and we market petroleum and petrochemical products primarily in Canada. Periodically we market third-party petroleum products. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2016, dated March 1, 2017 (the 2016 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three-month and six-month periods ended June 30, 2017, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2016 and the 2016 annual MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor's Annual Information Form dated March 1, 2017 (the 2016 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

References to "we", "our", "Suncor", or "the company" mean Suncor Energy Inc., and the company's subsidiaries and interests in associates and jointly controlled entities, unless the context otherwise requires.

Unless otherwise noted, all financial information has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), specifically International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board, which is within the framework of International Financial Reporting Standards (IFRS).

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, unless otherwise noted. Certain prior year amounts in the Consolidated Statements of Comprehensive Income (Loss) have been reclassified to conform to the current year's presentation.

References to Oil Sands operations exclude Suncor's interest in Syncrude operations.

Certain financial measures in this MD&A – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense, discretionary free cash flow, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating earnings (loss), Oil Sands operations cash operating costs, Syncrude cash operating costs and LIFO are defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to GAAP measures in the

Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Funds from (used in) operations, ROCE, discretionary free cash flow, refining margin and refining operating expense are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of this MD&A.

The company's financial and operational performance is potentially affected by a number of factors, including, but not limited to, the factors described within the Forward-Looking Information section of this MD&A. This MD&A contains forward-looking information based on Suncor's current expectations, estimates, projections and assumptions. This information is provided to assist readers in understanding the company's future plans and expectations and may not be appropriate for other purposes. Refer to the Forward-Looking Information section of this MD&A for information on the material risk factors and assumptions underlying our forward-looking information.

Certain crude oil and natural gas liquids volumes have been converted to mcfe on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcfe, boe or mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, conversion on a 6:1 basis may be misleading as an indication of value.

For a list of abbreviations that may be used in this MD&A, refer to the Common Abbreviations section of this MD&A.


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Net earnings (loss)

Oil Sands	(277	)	(1 063	)	25		(1 587	)

Exploration and Production	182		26		354		(8	)

Refining and Marketing	346		689		1 175		930

Corporate, Energy Trading and Eliminations	184		(387	)	233		187

Total	435		(735	)	1 787		(478	)

Operating earnings (loss)⁽¹⁾

Oil Sands	(277	)	(1 063	)	25		(1 587	)

Exploration and Production	182		26		354		(8	)

Refining and Marketing	346		689		821		930

Corporate, Energy Trading and Eliminations	(52	)	(217	)	(189	)	(400	)

Total	199		(565	)	1 011		(1 065	)

Funds from (used in) operations⁽¹⁾

Oil Sands	573		(202	)	1 682		61

Exploration and Production	438		302		919		563

Refining and Marketing	504		885		1 079		1 289

Corporate, Energy Trading and Eliminations	112		(69	)	(29	)	(315	)

Total	1 627		916		3 651		1 598

Capital and Exploration Expenditures⁽²⁾

Sustaining	894		752		1 293		1 223

Growth	765		869		1 572		1 813

Total	1 659		1 621		2 865		3 036


	Three months ended June 30		Six months ended June 30
	2017	2016	2017	2016

Production volumes by segment

Oil Sands (mbbls/d)	413.6	213.1	501.6	389.4

Exploration and Production (mboe/d)	125.5	117.6	130.0	121.6

Total (mboe/d)	539.1	330.7	631.6	511.0

Production mix

Crude oil and liquids / natural gas (%)	99/1	99/1	99/1	99/1

Refinery utilization (%)	94	87	94	89

Refinery crude oil processed (mbbls/d)	435.5	400.2	432.7	410.5

Suncor's consolidated net earnings for the second quarter of 2017 were $435 million, compared with a net loss of $735 million for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this MD&A. Other items affecting net earnings over these periods included:


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Net earnings (loss)	435		(735	)	1 787		(478	)

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(278	)	27		(381	)	(858	)

Non-cash mark to market loss on interest rate swaps and foreign currency derivatives⁽²⁾	32		70		32		160

Loss on early payment of long-term debt⁽³⁾	10		73		10		73

Gain on significant disposal⁽⁴⁾	—		—		(437	)	—

COS acquisition and integration costs⁽⁵⁾	—		—		—		38

Operating earnings (loss)⁽¹⁾	199		(565	)	1 011		(1 065	)

(1): Operating earnings (loss) is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Non-cash mark to market loss on interest rate swaps and foreign currency derivatives resulting from changes in long-term interest rates and foreign exchange rates in the Corporate segment.
(3): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains, in the Corporate segment.
(4): Gain of $354 million related to the sale of the company's lubricants business in the R&M segment, combined with a gain of $83 million on the sale of the company's interest in the Cedar Point wind facility in the Corporate segment.
(5): Transaction and related charges associated with the acquisition of Canadian Oil Sands Limited (COS) in the Corporate segment.

Suncor's consolidated operating earnings for the second quarter of 2017 were $199 million, compared to an operating loss of $565 million in the prior year quarter, with the improvement attributed to increased Oil Sands production, higher crude oil pricing and increased production from E&P and R&M, partially offset by a FIFO loss as compared to a FIFO gain in the prior period, and the production impacts associated with the facility incident at Syncrude and planned major maintenance at the majority of the company's oil sands assets. Operating earnings in the prior year quarter were significantly impacted by the production shut-in associated with the forest fires in the Fort McMurray area.

Suncor's consolidated operating earnings were $1.011 billion for the first six months of 2017, compared to an operating loss of $1.065 billion in the prior year period. The increase was attributable to improved crude price realizations, higher upstream production and R&M throughput, partially offset by a smaller FIFO gain in the current year period.


	Three months ended June 30		Six months ended June 30
($ millions)	2017	2016	2017	2016

Oil Sands	6	11	21	33

Exploration and Production	1	1	3	3

Refining and Marketing	3	6	12	22

Corporate, Energy Trading and Eliminations	9	11	55	73

Total share-based compensation expense	19	29	91	131

The after-tax share-based compensation expense decreased to $19 million during the second quarter of 2017, compared to $29 million during the prior year quarter, as a result of a greater share price decrease during the current period when compared to the share price decrease in the prior year quarter.

Commodity prices, refining crack spreads and foreign exchange rates are important factors that affect the results of Suncor's operations.

Average for the
three months ended
June 30

Average for the
six months ended
June 30

2017

2016

2017

2016

WTI crude oil at Cushing

US$/bbl

48.30

45.60

50.05

39.55

Dated Brent crude

US$/bbl

49.85

45.60

51.80

39.75

Dated Brent/Maya crude oil FOB price differential

US$/bbl

5.80

7.65

7.40

8.30

MSW at Edmonton

Cdn$/bbl

62.30

55.80

63.25

45.15

WCS at Hardisty

US$/bbl

37.20

32.30

37.25

25.80

Light/heavy differential for WTI at Cushing less WCS at Hardisty

US$/bbl

11.10

13.30

12.80

13.75

Condensate at Edmonton

US$/bbl

48.45

44.10

50.30

39.30

Natural gas (Alberta spot) at AECO

Cdn$/mcf

2.80

1.40

2.75

1.60

Alberta Power Pool Price

Cdn$/MWh

19.30

14.90

20.85

16.50

New York Harbor 3-2-1 crack⁽¹⁾

US$/bbl

16.35

16.10

14.45

13.95

Chicago 3-2-1 crack⁽¹⁾

US$/bbl

14.40

16.65

12.80

12.90

Portland 3-2-1 crack⁽¹⁾

US$/bbl

21.25

19.30

19.85

16.15

Gulf Coast 3-2-1 crack⁽¹⁾

US$/bbl

16.80

14.85

15.40

12.95

Exchange rate

US$/Cdn$

0.74

0.78

0.75

0.75

Exchange rate (end of period)

US$/Cdn$

0.77

0.77

0.77

0.77

(1): 3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

Suncor's sweet SCO price realizations are influenced primarily by the price of WTI at Cushing and by the supply and demand for sweet SCO from Western Canada. Price realizations in the second quarter of 2017 for sweet SCO were positively impacted by a higher WTI price of US$48.30/bbl, compared to US$45.60/bbl in the prior year quarter, as well as a favourable differential for SCO relative to WTI. Suncor produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton increased to $62.30/bbl compared to $55.80/bbl in the prior year quarter and prices for WCS at Hardisty increased to US$37.20/bbl from US$32.30 in the second quarter of 2016.

Bitumen production that Suncor does not upgrade is blended with diluent or SCO to facilitate delivery on pipeline systems. Net bitumen price realizations are therefore influenced by both prices for Canadian heavy crude oil (WCS at Hardisty is a common reference), prices for diluent (Condensate at Edmonton) and SCO. Bitumen price realizations can also be affected by bitumen quality and spot sales.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing increased to an average of US$49.85/bbl in the second quarter of 2017, compared to US$45.60/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark increased to $2.80/mcf in the second quarter of 2017, from $1.40/mcf in the prior year quarter.

Suncor's refining margins are influenced primarily by 3-2-1 crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates, and by light/heavy and light/sour crude differentials. More complex refineries can earn greater refining margins by processing less expensive, heavier crudes. Crack spreads do not necessarily reflect the margins of a specific refinery. Crack spreads are based on current crude feedstock prices whereas actual refining margins are based on FIFO inventory accounting, where a delay exists between the time that feedstock is purchased and when it is processed and sold to a third party. A FIFO loss normally reflects a declining price environment for crude oil and finished products, whereas FIFO gains reflect an increasing price environment for crude oil and finished products. Specific refinery margins are further impacted by actual crude purchase costs, refinery configuration, production mix and realized prices for refined products sales in markets unique to each refinery.

Excess electricity produced in Suncor's Oil Sands operations business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the Oil Sands operations cash operating cost per barrel metric. The Alberta power pool price increased to an average of $19.30/MWh in the second quarter of 2017, compared with $14.90/MWh in the prior year quarter.

The majority of Suncor's revenues from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. In the second quarter of 2017, the Canadian dollar weakened in relation to the U.S. dollar as the average exchange rate decreased to US$0.74 per one Canadian dollar from US$0.78 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the second quarter of 2017 when compared to the prior year quarter.

Suncor also has assets and liabilities, notably approximately 70% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. An increase in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date decreases the amount of Canadian dollars required to settle U.S. dollar denominated obligations.


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Gross revenues	2 498		1 160		5 788		3 199

Less: Royalties	(37	)	(9	)	(98	)	(28	)

Operating revenues, net of royalties	2 461		1 151		5 690		3 171

Net (loss) earnings	(277	)	(1 063	)	25		(1 587	)

Operating (loss) earnings⁽¹⁾	(277	)	(1 063	)	25		(1 587	)

Oil Sands operations	37		(797	)	*330*		(1 314	)

Oil Sands ventures	*(314*	)	(266	)	*(305*	)	(273	)

Funds from (used in) operations⁽¹⁾	573		(202	)	1 682		61

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings for Oil Sands operations were $37 million in the second quarter of 2017, compared to an operating loss of $797 million in the prior year quarter. The improvement was due to increased crude oil production combined with higher crude price realizations, consistent with increased benchmark pricing, partially offset by the avoidance of operating costs during the second quarter of 2016 while operations were shut in and higher natural gas costs in the second quarter of 2017.

The operating loss for Oil Sands ventures was $314 million in the second quarter of 2017, compared to an operating loss of $266 million in the prior year quarter, with higher crude oil production and price realizations being more than offset by the impact of increased repair costs associated with the Syncrude Mildred Lake facility incident occurring near the end of the first quarter of 2017, the avoidance of operating costs while operations were shut in during the second quarter of 2016 and higher natural gas costs in the second quarter of 2017.

Operating earnings at both Oil Sands ventures and Oil Sands operations in the second quarter of 2016 were significantly impacted by the production shut-in associated with the forest fires in the Fort McMurray area.


	Three months ended June 30		Six months ended June 30
(mbbls/d)	2017	2016	2017	2016

Upgraded product (SCO and diesel)	288.6	86.4	310.6	204.3

Non-upgraded bitumen	64.0	91.1	89.7	110.9

Oil Sands operations	352.6	177.5	400.3	315.2

Oil Sands ventures – Syncrude	61.0	35.6	101.3	74.2

Total	413.6	213.1	501.6	389.4

(1): Bitumen production from Oil Sands Base operations is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor's own refineries. Yields of SCO and diesel from Suncor's upgrading process are approximately 79% of bitumen feedstock input. All of the bitumen produced at Syncrude is upgraded to sweet SCO.

Oil Sands operations production was 352,600 bbls/d in the second quarter of 2017, compared to 177,500 bbls/d in the prior year quarter, with the increase primarily driven by the loss of production associated with the forest fires in the Fort McMurray area in the prior year quarter. Production in the second quarter of 2017 was impacted by planned upgrader maintenance completed in the period, as well as a planned turnaround at Firebag. Upgrader utilization at Oil Sands operations in the second quarter of 2017 was 83%, compared to 25% in the prior year quarter. Production at Oil Sands operations returned to normal operating rates by the end of the quarter.


	Three months ended June 30		Six months ended June 30
(mbbls/d)	2017	2016	2017	2016

Oil Sands operations sales volumes

Sweet SCO	104.4	29.0	114.6	80.6

Diesel	29.6	3.4	29.9	14.1

Sour SCO	160.1	76.3	169.8	124.5

Upgraded product	294.1	108.7	314.3	219.2

Non-upgraded bitumen	86.0	108.1	95.4	121.3

Oil Sands operations	380.1	216.8	409.7	340.5

Oil Sands ventures – Syncrude	61.0	35.6	101.3	74.2

Total	441.1	252.4	511.0	414.7

Sales volumes for Oil Sands operations increased to 380,100 bbls/d in the second quarter of 2017 from 216,800 bbls/d in the prior year quarter due to the same factors noted above.

Suncor's share of Syncrude production was 61,000 bbls/d in the second quarter of 2017, compared to 35,600 bbls/d in the prior year quarter. The increase is attributed to production being shut in during the second quarter of 2016 due to the forest fires in the Fort McMurray area and an additional 5% working interest acquired partway through the second quarter of 2016, partially offset by the facility incident late in the first quarter of 2017 and completion of the planned upgrader turnaround in the second quarter of 2017. Syncrude upgrader reliability was 33% in the second quarter of 2017, compared to 25% in the prior year quarter.


	Three months ended June 30		Six months ended June 30
	2017	2016	2017	2016

Oil Sands Base

Bitumen production (mbbls/d)	293.1	66.8	298.2	185.4

Bitumen ore mined (thousands of tonnes per day)	448.3	106.1	458.7	277.7

Bitumen ore grade quality (bbls/tonne)	0.65	0.63	0.65	0.67

In Situ

Bitumen production – Firebag (mbbls/d)	110.9	121.8	156.6	160.4

Bitumen production – MacKay River (mbbls/d)	30.0	13.1	32.8	25.0

Total In Situ bitumen production (mbbls/d)	140.9	134.9	189.4	185.4

Total Oil Sands Operations Bitumen production (mbbls/d)	434.0	201.7	487.6	370.8

Steam-to-oil ratio – Firebag	2.6	2.6	2.6	2.6

Steam-to-oil ratio – MacKay River	3.2	3.2	3.1	3.0

Bitumen production at Oil Sands operations in the second quarter of 2017 increased to 434,000 bbls/d, compared to 201,700 bbls/d in the prior year quarter, due to production being shut in during the second quarter of 2016 in response to the forest fires in the Fort McMurray area. Production in the second quarter of 2017 was impacted by planned upgrader maintenance, which was completed in the period, as well as the first five-year turnaround of the expanded Firebag central facilities and unplanned maintenance at MacKay River.


Net of transportation costs, but before royalties	Three months ended June 30				Six months ended June 30
($/bbl)	2017		2016		2017		2016

Oil Sands operations

SCO and diesel	60.48		47.51		61.50		41.44

Bitumen	30.55		18.21		29.41		11.67

Crude sales basket (all products)	53.71		32.90		53.99		30.83

Crude sales basket, relative to WTI	(11.56	)	(25.56	)	(12.74	)	(21.90	)

Oil Sands ventures

Syncrude – sweet SCO	60.44		57.64		64.31		51.02

Syncrude, relative to WTI	(4.83	)	(0.82	)	(2.42	)	(1.71	)

Average price realizations from Oil Sands operations increased to $53.71/bbl in the second quarter of 2017 from $32.90/bbl in the prior year quarter, due to higher WTI benchmark prices, improved SCO and heavy crude differentials, and a higher proportion of SCO production in the second quarter of 2017.

Average price realizations at Syncrude increased to $60.44/bbl in the second quarter of 2017 from $57.64/bbl in the prior year quarter due to the increase in the WTI benchmark price and improved SCO differentials, partially offset by the sale of intermediate sour product to maintain minimum production rates and avoid a full shutdown and restart as a result of the facility incident.

Royalties for the Oil Sands segment were higher in the second quarter of 2017 compared to the prior year quarter, primarily due to higher production and improved bitumen pricing.

Operating and transportation expenses for the second quarter of 2017 increased from the prior year quarter as a result of costs avoided during the second quarter of 2016 at both Oil Sands operations and Syncrude while operations were shut in, increased repair costs at Syncrude due to the facility incident late in the first quarter of 2017, increased natural gas pricing and consumption, and the additional 5% Syncrude working interest acquired in the second quarter of 2016, partially offset by the impact of Suncor's cost reduction initiatives at Oil Sands operations. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs for Oil Sands operations.

DD&A and exploration expenses for the second quarter of 2017 were lower in comparison to the same period of 2016, due to lower depreciation associated with a reduced asset cost base at Oil Sands operations and a decrease in exploration expense more than offsetting the increased working interest in Syncrude.


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Oil Sands operations cash operating cost⁽¹⁾ reconciliation

Operating, selling and general expense (OS&G)	1 575		1 288		3 128		2 723

Syncrude OS&G	(551	)	(364	)	(1 134	)	(698	)

Non-production costs⁽²⁾	(11	)	(32	)	(32	)	(65	)

Excess power capacity and other⁽³⁾	(73	)	(50	)	(122	)	(81	)

Inventory changes	(47	)	(87	)	(36	)	(125	)

Oil Sands operations cash operating costs⁽¹⁾	893		755		1 804		1 754

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	27.80		46.80		24.90		30.60

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	551		364		1 134		698

Non-production costs⁽²⁾	(8	)	3		(14	)	(9	)

Syncrude cash operating costs⁽¹⁾	543		367		1 120		689

Syncrude cash operating costs ($/bbl)⁽¹⁾	97.80		113.55		61.05		51.20

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Significant non-production costs include, but are not limited to, share-based compensation expense and research expenses.
(3): Excess power capacity and other includes, but is not limited to, the operational revenue impacts of excess power from a cogeneration unit and the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor.

In the second quarter of 2017, Oil Sands operations cash operating costs per barrel decreased to $27.80, compared to $46.80 in the prior year quarter, primarily as a result of higher production, which was due to the outage in response to the forest fires during the prior year quarter. Total Oil Sands operations cash operating costs increased to $893 million from $755 million in the prior year quarter, with lower costs in the second quarter of 2016 attributed to the avoidance of certain operating expenses while production was shut in. Costs in the second quarter of 2017 reflect the continued impact of the company's cost reduction initiatives.

In the second quarter of 2017, non-production costs, which are excluded from Oil Sands operations cash operating costs, were lower than the prior year quarter, primarily due to a decrease in share-based compensation expense when compared to the prior year quarter as well as the prior period including a charge associated with an early termination of a third-party operating arrangement.

Excess power capacity and other for the second quarter of 2017 represents a larger reduction to Oil Sands operations cash operating costs than the second quarter of 2016, primarily attributed to higher non-monetary expenses related to a gas swap arrangement with a third-party processor due to increased production.

Inventory changes in the second quarter of 2017 represent a smaller draw of inventory than in the prior year quarter, due to the increased draw of inventory associated with the production shut-in during the second quarter of 2016.

In the second quarter of 2017, Syncrude cash operating costs per barrel were $97.80 compared to $113.55 in the prior year period with the production shut-in associated with the forest fires in 2016 having a greater impact than the combination of the facility incident and major maintenance activities in the current period. Suncor's share of Syncrude cash operating costs increased to $543 million from $367 million in the previous year quarter due to repairs associated with the facility incident late in the first quarter of 2017, costs avoided during the second quarter of 2016 while operations were shut in, additional Syncrude working interest acquired in the second quarter of 2016, and increased natural gas pricing and consumption.

Oil Sands segment operating earnings for the first six months of 2017 were $25 million, compared to an operating loss of $1.587 billion for the same period in 2016. Operating earnings improved as a result of higher production due to the impact of the forest fires in the Fort McMurray area during the second quarter of 2016, higher crude price realizations and lower Oil Sands operations operating expenses attributed to the company's continued cost reduction initiatives, partially offset by the impact of major maintenance events at the majority of the company's Oil Sands assets, the facility incident at Syncrude, increased operating and maintenance expenses at Syncrude, and higher natural gas costs due to an increase in natural gas benchmark pricing and consumption.

Funds from operations for the first six months of 2017 were $1.682 billion for the segment, compared to $61 million for the same period in 2016, with the increase primarily due to the same factors that influenced operating earnings noted above.

Oil Sands operations cash operating costs per barrel averaged $24.90 for the first six months of 2017, a decrease from an average of $30.60 for the first six months of 2016. The decrease was largely driven by higher production due to the impact of the forest fires in the Fort McMurray area in the prior year, as well as the company's cost reduction initiatives, partially offset by the impact of planned maintenance activities in the second quarter of 2017 and higher natural gas pricing and consumption.

Syncrude cash operating costs per barrel averaged $61.05 for the first six months of 2017, an increase from an average of $51.20 for the first six months of 2016, due to increased operating and maintenance costs and the production impacts of the facility incident and the planned upgrader turnaround combined with accelerated coker maintenance originally scheduled for the fourth quarter of 2017, partially offset by higher overall production due to the impact of the forest fires in the Fort McMurray area during the second quarter of 2016.

The company plans to commence maintenance at Upgrader 1 in the third quarter of 2017. The anticipated impact of this maintenance has been reflected in the company's 2017 guidance.


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Gross revenues	852		624		1 772		1 155

Less: Royalties	(121	)	(45	)	(244	)	(74	)

Operating revenues, net of royalties	731		579		1 528		1 081

Net earnings (loss)	182		26		354		(8	)

Operating earnings (loss)⁽¹⁾	182		26		354		(8	)

E&P Canada	43		40		60		21

E&P International	*139*		(14	)	*294*		(29	)

Funds from operations⁽¹⁾	438		302		919		563

(1): Non-GAAP financial measures. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings of $43 million for E&P Canada increased from $40 million in the prior year quarter, as a result of higher production and improved crude price realizations, partially offset by higher DD&A and royalties due to the increase in production, and the prior year quarter including insurance proceeds related to Terra Nova property damage.

Operating earnings of $139 million for E&P International improved from an operating loss of $14 million in the prior year quarter, which included the impairment of the Beta development in Norway. Current quarter earnings were also improved by lower DD&A, increased crude price realizations and production from Libya, partially offset by lower production at Buzzard.


	Three months ended June 30		Six months ended June 30
(mbbls/d)	2017	2016	2017	2016

E&P Canada

Terra Nova (mbbls/d)	11.0	5.4	12.9	9.0

Hibernia (mbbls/d)	30.0	24.6	30.1	24.4

White Rose (mbbls/d)	12.9	11.7	13.0	12.7

North America Onshore (mboe/d)	1.8	2.7	2.3	2.9

	55.7	44.4	58.3	49.0

E&P International

Buzzard (mboe/d)	45.3	52.7	47.1	53.0

Golden Eagle (mboe/d)	20.1	20.5	20.2	19.6

United Kingdom (mboe/d)	65.4	73.2	67.3	72.6

Libya (mbbls/d)	4.4	—	4.4	—

	69.8	73.2	71.7	72.6

Total Production (mboe/d)	125.5	117.6	130.0	121.6

Production mix (liquids/gas) (%)	97/3	98/2	97/3	98/2

E&P Canada production averaged 55,700 boe/d in the second quarter of 2017, compared to 44,400 boe/d in the prior year quarter. The increase was primarily due to planned maintenance at Terra Nova in the prior year quarter and higher production at Hibernia, with new wells being brought online subsequent to the second quarter of 2016.

E&P International production averaged 69,800 boe/d in the second quarter of 2017, compared to 73,200 boe/d in the prior year quarter, with natural declines at Buzzard being partially offset by production from Libya.


	Three months ended June 30		Six months ended June 30
Net of transportation costs, but before royalties	2017	2016	2017	2016

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	64.65	60.30	66.34	51.35

E&P Canada – Natural gas ($/mcfe)	2.62	1.14	2.55	1.26

E&P International ($/boe)	61.81	53.43	63.86	47.30

Price realizations for crude oil from E&P Canada and E&P International were higher in the second quarter of 2017, compared to the prior year quarter, primarily due to an increase in benchmark crude pricing and favourable foreign exchange rates.

Royalties were higher in the second quarter of 2017, compared with the prior year quarter, due to increased production from E&P Canada combined with improved crude prices.

Operating and transportation expenses were comparable to the prior year quarter. Continued focus on cost reduction and favourable foreign exchange that reduced expenses in the U.K. were partially offset by increased activity in Libya.

DD&A expense decreased in the second quarter of 2017, compared to the prior year quarter, due to lower depletion rates at Buzzard and the absence of impairment charges in the current period, partially offset by higher East Coast Canada production. The second quarter of 2016 included an impairment charge for the Beta development in Norway.

Operating earnings for E&P in the first six months of 2017 were $354 million, compared to an operating loss of $8 million for the first six months of 2016. The increase was primarily due to higher crude price realizations, increased production, lower DD&A and decreased operating costs, partially offset by higher royalties, attributed to crude pricing and production increases, and additional costs associated with drilling at the Shelburne Basin off the east coast of Canada, which predominantly took place late in 2016.

Funds from operations were $919 million for the first six months of 2017, compared to $563 million for the same period in 2016, and increased due to higher price realizations, increased production and lower operating costs, partially offset by higher royalties.

A planned three-week maintenance event at Terra Nova has been scheduled to commence in the third quarter of 2017. The anticipated impact of this maintenance has been reflected in the company's 2017 guidance.


	Three months ended June 30		Six months ended June 30
($ millions)	2017	2016	2017		2016

Operating revenues	4 744	4 590	9 397		8 181

Net earnings	346	689	1 175		930

Adjusted for:

Gain on significant disposal⁽¹⁾	—	—	(354	)	—

Operating earnings⁽²⁾	346	689	821		930

Refining and Supply	*262*	581	*656*		756

Marketing	84	108	*165*		174

Funds from operations⁽²⁾	504	885	1 079		1 289

(1): After-tax gain related to the sale of the company's lubricants business.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings on a FIFO basis were $346 million, compared to $689 million in the prior year quarter, with the decrease explained below. Using a LIFO⁽¹⁾ method of inventory valuation, which management uses to assess performance, earnings were $384 million compared to $413 million in the prior year quarter and improved after removing the impact of the disposal of the lubricants business in the first quarter of 2017.

Refining and Supply operating earnings were $262 million in the second quarter of 2017, compared to $581 million in the prior year quarter. The decrease was primarily due to realizing a FIFO loss of $38 million, as compared to a FIFO gain in the prior year period of $275 million, for a quarter-over-quarter impact of $313 million. In addition, improved benchmark cracking margins and product location differentials were more than offset by narrower crude differentials.

Marketing activities contributed $84 million to operating earnings in the second quarter of 2017, compared to $108 million in the prior year quarter, which included $38 million of operating earnings from the lubricants business disposed of in the first quarter of 2017. After removing the impact of the lubricants business, marketing operating earnings improved due to higher wholesale and retail margins, as well as strong retail and wholesale sales volumes.

During the first quarter of 2017, Suncor completed the sale of its Petro-Canada lubricants business, which contributed $45 million in net earnings and $72 million in funds from operations in the second quarter of 2016. The impact of the lubricants sale has been reflected in Financing Expense and Other in the bridge analysis above.


	Three months ended June 30		Six months ended June 30
	2017	2016	2017	2016

Crude oil processed (mbbls/d)

Eastern North America	208.6	181.7	211.6	196.9

Western North America	226.9	218.5	221.1	213.6

Total	435.5	400.2	432.7	410.5

Refinery utilization⁽¹⁾ (%)

Eastern North America	94	82	95	89

Western North America	95	91	92	89

Total	94	87	94	89

Refined product sales (mbbls/d)

Gasoline	236.8	251.3	233.4	240.6

Distillate	191.2	190.0	191.7	181.1

Other	93.9	91.2	89.9	89.3

Total	521.9	532.5	515.0	511.0

Refining margin⁽²⁾ ($/bbl)	18.85	21.65	20.55	20.35

Refining operating expense⁽²⁾ ($/bbl)	5.05	5.40	5.25	5.25

(1): Refinery utilization is the amount of crude oil and natural gas plant liquids run through crude distillation units, expressed as a percentage of the capacity of these units.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Refinery crude throughput in the second quarter of 2017 improved to 435,500 bbls/d, compared to 400,200 bbls/d in the prior year quarter. In Eastern North America, the average volume of crude oil processed increased in the second quarter of 2017 to 208,600 bbls/d compared to 181,700 bbls/d during the same period in 2016, due to lower planned maintenance activity at both the Sarnia and Montreal refineries in the second quarter of 2017 combined with improved crude availability. The average volume of crude oil processed in Western North America increased to 226,900 bbls/d in the second quarter of 2017 from 218,500 bbls/d in the prior year quarter, primarily due to lower planned maintenance at the Commerce City refinery and improved crude availability.

Total refined product sales were 521,900 bbls/d in the second quarter of 2017, compared to 532,500 bbls/d in the prior year quarter, with increases in wholesale and retail volumes being more than offset by a decrease in third-party gasoline purchases for resale.

Refined product margins in Refining and Supply were lower in the second quarter of 2017 compared with the prior year quarter, and were impacted primarily by the following factors:

Marketing margins in the second quarter of 2017, excluding the impact of the sale of the lubricants business in the first quarter of 2017, were higher than margins in the prior year quarter, primarily due to increased wholesale and retail sales volumes and margins.

After removing the impact of the lubricants business, which was sold in the first quarter of 2017, operating expenses in the second quarter of 2017 were higher than the prior year quarter, with reduced refinery operating costs being more than offset by higher energy input prices and increased variable selling costs associated with the increase in retail sales volumes.

Financing Expense and Other includes the net impact of the sale of the lubricants business in the first quarter of 2017.

For the first six months of 2017, Refining and Marketing segment operating earnings were $821 million, compared to $930 million for the first six months of 2016. The decrease in operating earnings was due primarily to a lower FIFO gain in the current year period and the sale of the lubricants business, partially offset by improved overall benchmark crack spreads, favourable crude differentials, higher refinery throughput resulting from lower planned maintenance activity and record retail sales volumes for the first half of 2017. For the first six months of 2017, the impact of the FIFO method of inventory valuation, as used by the company, relative to an estimated LIFO method, had a positive impact to operating earnings and funds from operations of $5 million after-tax, compared to $83 million after-tax in the first six months of 2016.

Funds from operations were $1.079 billion for the first six months of 2017, compared to $1.289 billion for the first six months of 2016, and decreased primarily due to the same factors that influenced operating earnings.

Suncor completed the sale of its Petro-Canada lubricants business during the first quarter of 2017, which contributed $8 million in net earnings and $11 million in funds from operations for the first six months of 2017, compared to $58 million in net earnings and $100 million in funds from operations for the first six months of 2016.


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Net earnings (loss)	184		(387	)	233		187

Adjusted for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(278	)	27		(381	)	(858	)

Non-cash mark to market loss on interest rate swaps and foreign currency derivatives⁽¹⁾	32		70		32		160

Non-cash loss on early payment of long-term debt⁽²⁾	10		73		10		73

Gain on significant disposal⁽³⁾	—		—		(83	)	—

COS acquisition and related costs⁽⁴⁾	—		—		—		38

Operating (loss) earnings⁽⁵⁾	(52	)	(217	)	(189	)	(400	)

Renewable Energy	1		3		(1	)	13

Energy Trading	(4	)	(6	)	*(15*	)	(8	)

Corporate	*(75*	)	(183	)	*(215*	)	(409	)

Eliminations	26		(31	)	42		4

Funds from (used in) operations⁽⁵⁾	112		(69	)	(29	)	(315	)

(1): Non-cash mark to market after-tax loss on interest rate swaps and foreign currency derivatives resulting from changes in long-term interest rates and foreign exchange rates.
(2): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains.
(3): After-tax gain related to the sale of the company's interest in the Cedar Point wind facility.
(4): After-tax transaction and related charges associated with the acquisition of COS.
(5): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Renewable Energy had operating earnings of $1 million in the second quarter of 2017, compared to $3 million in the prior year quarter. The decrease was due to lower production associated with the sale of the company's interest in the Cedar Point wind facility, which was effective January 1, 2017.

Subsequent to the end of the quarter, Suncor completed the sale of its interest in the Ripley wind facility for estimated proceeds of $48 million, subject to customary post-closing adjustments.

The operating loss for Energy Trading was $4 million in the quarter, compared to an operating loss of $6 million in the prior year quarter, with natural gas trading partially offsetting weak crude location spreads.

The Corporate operating loss was $75 million for the second quarter of 2017, compared to an operating loss of $183 million for the prior year quarter. The decrease was primarily due to higher capitalized interest, a decrease in functional costs attributed to the company's continued cost reduction efforts and lower interest expense as a result of debt repayments in the second quarters of 2017 and 2016. The company capitalized $196 million of its borrowing costs in the second quarter of 2017 as part of the cost of major development assets and construction projects in progress, compared to $140 million in the prior year quarter.

Eliminations reflect the elimination of profit on crude oil sales from Oil Sands and East Coast Canada to Refining and Supply. Consolidated profits are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the second quarter of 2017, the company realized $26 million of after-tax intersegment profit, compared to eliminating $31 million of after-tax intersegment profit in the prior year quarter, with the change attributed to a decrease in intersegment inventory levels.

Corporate, Energy Trading and Eliminations funds from operations for the second quarter of 2017 were $112 million, compared to funds used in operations of $69 million in the prior year period. In addition to the factors noted above in operating earnings, funds from operations were favourably impacted by tax recoveries associated with the early repayment of debt.

The operating loss for Corporate, Energy Trading and Eliminations for the first six months of 2017 was $189 million, compared to an operating loss of $400 million for the first six months of 2016. In addition to the factors noted above, the operating loss for the first six months of 2017 was favourably impacted by a realized gain on forward interest rate swaps and lower share-based compensation. The company capitalized $370 million of its borrowing costs in the first six months of 2017 as part of the cost of major development assets and construction projects, compared with $281 million of capitalized borrowing costs in the first six months of 2016, with the increase due to higher accumulated expenditures on major growth projects.

Corporate, Energy Trading and Eliminations funds used in operations for the first six months of 2017 were $29 million, compared to $315 million in the prior year period. In addition to the factors noted above in operating earnings, funds from operations were favourably impacted by tax recoveries associated with the early repayment of debt.


	Three months ended June 30				Six months ended June 30
($ millions)	2017		2016		2017		2016

Oil Sands	1 500		1 254		2 559		2 361

Exploration and Production	215		275		442		546

Refining and Marketing	134		229		226		401

Corporate, Energy Trading and Eliminations	6		3		8		9

Total capital and exploration expenditures	1 855		1 761		3 235		3 317

Less: capitalized interest on debt	(196	)	(140	)	(370	)	(281	)

	1 659		1 621		2 865		3 036

Three months ended June 30, 2017

Six months ended June 30, 2017

($ millions)

Sustaining(2)

Growth(3)

Total

Sustaining(2)

Growth(3)

Total

Oil Sands

Oil Sands Base

390

456

573

135

708

In Situ

120

—

120

174

180

Oil Sands ventures

239

537

776

304

1 092

1 396

Exploration and Production

162

167

339

347

Refining and Marketing

134

—

134

226

—

226

Corporate, Energy Trading and Eliminations

—

894

765

1 659

1 293

1 572

2 865

(1): Capital expenditures in this table exclude capitalized interest on debt.
(2): Sustaining capital expenditures include capital investments that i) ensure compliance or maintain relations with regulators and other stakeholders; ii) improve efficiency and reliability of operations or maintain productive capacity by replacing component assets at the end of their useful lives; iii) deliver existing proved developed reserves for E&P operations; or iv) maintain current production capacities at existing Oil Sands and R&M operations.
(3): Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands and R&M operations; ii) new facilities or operations that increase overall production; iii) new infrastructure that is required to support higher production levels; iv) new reserves or a positive change in the company's reserves profile in E&P operations; or v) margin improvement, by increasing revenues or reducing costs.

In the second quarter of 2017, total capital and exploration expenditures were $1.659 billion (excluding capitalized interest). Capital and exploration expenditures in the second quarter of 2017 were comparable to the prior year quarter, with increased sustaining capital related to major maintenance activities and turnarounds more than offsetting decreased growth expenditures predominantly associated with Fort Hills and Hebron as peak construction activity for those projects winds down.

Oil Sands Base capital and exploration expenditures were $456 million in the second quarter of 2017, the majority of which were directed towards sustaining activities primarily focused on completion of planned upgrader maintenance. Capital expenditures also included various reliability and sustainment projects across the operations. Growth capital at Oil Sands Base was focused on the East Tank Farm Development, which will support market access for Fort Hills bitumen production. Subsequent to the end of the second quarter, the East Tank Farm Development was commissioned and will support Fort Hills following first oil at the end of 2017.

In Situ capital and exploration expenditures were $120 million and were directed towards sustaining activities, including the first full five-year turnaround of the expanded Firebag central facilities. Sustaining capital also included ongoing well pad construction that is expected to maintain existing production levels at Firebag and MacKay River.

Oil Sands ventures capital and exploration expenditures were $776 million, of which growth capital expenditures were $537 million and sustaining capital expenditures were $239 million.

Growth capital was primarily for the Fort Hills mining project, with the project now 90% complete and the handover of the ore processing and main primary extraction assets to operations occurring in the period. Activity continued at the secondary extraction facilities, the last area under major construction required to bring the project to first oil, which remains on target for the end of 2017.

Sustaining capital expenditures in the second quarter of 2017 at Fort Hills were focused on early-works sustaining activities that will support the execution of the Fort Hills mine and tailings plan following the commencement of production.

Syncrude sustaining capital was primarily focused on the upgrader turnaround, which was completed in mid-July, advanced coker maintenance originally planned to be completed in the fourth quarter of 2017 and rebuild costs associated with the facility incident that occurred in the first quarter of 2017. Planned coker maintenance was brought forward in order to help mitigate the impact of shutting in production for repairs associated with the facility incident late in the first quarter of 2017. Capital expenditures also included various reliability and sustainment projects across the operations to support the execution of the mine-tailings plan.

Development of the Hebron project continued in the second quarter of 2017, with the platform towed out to the final offshore location and successfully positioned on the sea floor. Drilling activities are on schedule and first oil from the project continues to be on track for late 2017. Growth capital at E&P was also directed towards development drilling at Hibernia and White Rose and development work on the Norwegian Oda project.

During the second quarter of 2017, the partners sanctioned the West White Rose Project with first oil targeted for 2022. Husky Energy Inc. is the project operator and Suncor holds a blended working interest of approximately 26%. The project is expected to extend the life of the existing White Rose facilities, with the company's share of peak oil production estimated to be 20,000 boe/d. Suncor's estimated net share of the project cost is approximately $1.4 billion, and major development activity is not expected to begin until 2018.

R&M capital expenditures were $134 million and were primarily related to ongoing sustainment of operations, including planned refinery maintenance, enhancements to retail operations and information technology upgrades.

Corporate capital expenditures were $6 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended June 30
	2017	2016

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	6.2	(4.9	)

Including major projects in progress	4.9	(4.1	)

Net debt to funds from operations⁽²⁾ (times)	1.7	3.0

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	3.8	(3.6	)

Funds from operations basis⁽²⁾⁽⁴⁾	9.4	5.6

(1): Non-GAAP financial measure. ROCE is reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Funds from operations and metrics that use funds from operations are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(4): Funds from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.

Suncor's capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, available lines of credit and the divestiture of non-core assets. Suncor's management believes the company will have the capital resources to fund its planned 2017 capital spending program of $5.4 to $5.6 billion and to meet current and future working capital requirements through cash balances and cash equivalents, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, divesting of non-core assets and accessing capital markets. The company's cash flow provided by operating activities depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

The company has invested cash in short-term financial instruments that are presented as cash and cash equivalents. The objectives of the company's short-term investment portfolio are to ensure the preservation of capital, maintain adequate liquidity to meet Suncor's cash flow requirements and deliver competitive returns derived from the quality and diversification of investments within acceptable risk parameters. The maximum weighted average term to maturity of the short-term investment portfolio is not expected to exceed six months, and all investments will be with counterparties with investment grade debt ratings.

Cash and cash equivalents decreased to $2.352 billion during the first six months of 2017 from $3.016 billion at December 31, 2016. The decrease is primarily due to the repayment of US$1.250 billion in long-term indebtedness, the purchase of the company's own shares under the normal course issuer bid (NCIB), and capital and exploration expenditures and dividend requirements exceeding cash flow provided by operating activities, partially offset by the proceeds from the sale of the company's lubricants business and its interest in the Cedar Point wind facility and an increase in short-term indebtedness.

As capital spending on major growth projects starts to ramp down, the company expects that less cash will be required for funding purposes in the future, supporting the repayment of long-term debt and increased returns to shareholders in the form of share repurchases, subject to prevailing economic conditions and other relevant factors.

As at June 30, 2017, the weighted average term to maturity of the short-term investment portfolio was approximately 13 days.

Available lines of credit at June 30, 2017 decreased to $5.697 billion, compared to $7.467 billion at December 31, 2016, as a result of the cancellation of a $950 million credit facility that was acquired through the acquisition of COS combined with an increase in short-term indebtedness. The cancelled credit facility is no longer expected to be required for liquidity purposes and the termination will reduce future financing expense.

Management of debt levels continues to be a priority for Suncor given the company's long-term growth plans and the current pricing environment. Suncor believes a phased and flexible approach to existing and future growth projects should assist the company in maintaining its ability to manage project costs and debt levels.

During the second quarter of 2017, Suncor repaid US$1.250 billion of 6.10% notes originally scheduled to mature June 1, 2018 to reduce financing costs and provide ongoing balance sheet flexibility. A premium was paid to early settle the debt, with interest savings more than offsetting this amount in the future. The repayment was primarily funded with the proceeds from asset divestments realized in the first quarter of 2017.

Suncor is subject to financial and operating covenants related to its bank debt and public market debt. Failure to meet the terms of one or more of these covenants may constitute an "event of default" as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its financial covenant that requires total debt to not exceed 65% of its total debt plus shareholders' equity. At June 30, 2017, total debt to total debt plus shareholders' equity was 26.4% (December 31, 2016 – 28.1%). The company is currently in compliance with all operating covenants.


($ millions, except as noted)	June 30 2017	December 31 2016

Short-term debt	2 019	1 273

Current portion of long-term debt	1 533	54

Long-term debt	12 580	16 103

Total debt	16 132	17 430

Less: Cash and cash equivalents	2 352	3 016

Net debt	13 780	14 414

Shareholders' equity	44 887	44 630

Total debt plus shareholders' equity	61 019	62 060

Total debt to total debt plus shareholders' equity (%)	26.4	28.1


	Three and six months ended June 30, 2017
($ millions)	Q2		YTD

Total debt – beginning of period	16 793		17 430

Decrease in long-term debt	(1 740	)	(1 754	)

Increase in short-term debt	1 338		827

Foreign exchange on debt, and other	(259	)	(371	)

Total debt – June 30, 2017	16 132		16 132

Less: Cash and cash equivalents – June 30, 2017	2 352		2 352

Net debt – June 30, 2017	13 780		13 780

The company's total debt position improved in the second quarter due to the early repayment of US$1.250 billion of 6.10% notes originally scheduled to mature on June 1, 2018 and the impact of favourable foreign exchange rates on U.S. dollar denominated debt, partially offset by an increase in short-term borrowings.

As at July 24, 2017, the total number of common shares outstanding was 1,659,365,514 and the total number of exercisable and non-exercisable common share options outstanding was 56,341,069. Once exercisable, each outstanding common share option is convertible into one common share.

The company may repurchase shares pursuant to the NCIB through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative trading platforms. Under the NCIB, the company may purchase for cancellation up to approximately $2.0 billion worth of its common shares from May 2, 2017 to May 1, 2018 and has agreed that it will not purchase more than 50,079,795 common shares, which was equal to approximately 3% of Suncor's issued and outstanding common shares.

During the second quarter of 2017, the company repurchased 7,220,753 common shares at an average price of $40.93 per share, for $296 million. Suncor did not purchase any of its shares pursuant to a normal course issuer bid during the first six months of 2016.

Contractual Obligations, Commitments, Guarantees, and Off-Balance Sheet Arrangements

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments. Suncor has included these items in the Financial Condition and Liquidity section of its 2016 annual MD&A and has provided an update below. The company does not believe that it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company's financial performance or financial condition, results of operations, liquidity or capital expenditures.

During the six months ended June 30, 2017, the company decreased its commitments by approximately $1.3 billion (undiscounted), which is primarily related to the early repayment of US$1.250 billion of 6.10% notes originally scheduled to mature on June 1, 2018 and the reduction in commitments associated with the disposal of Suncor's lubricants business and its interest in the Cedar Point wind facility, partially offset by a lodging services commitment that supports Suncor's Oil Sands Base operations and the recognition of incremental Hebron decommissioning costs following the milestones achieved during the second quarter of 2017.

Trends in Suncor's quarterly revenue, earnings and funds from operations⁽¹⁾ are driven primarily by production volumes, which can be significantly impacted by major maintenance events, changes in commodity prices, refining crack spreads, foreign exchange rates and other significant events impacting operations, such as the Syncrude facility incident that occurred late in the first quarter of 2017, which significantly impacted the second quarter of 2017, and the forest fires in the Fort McMurray area in the second quarter of 2016.


Three months ended ($ millions, unless otherwise noted)	Jun 30 2017	Mar 31 2017	Dec 31 2016		Sep 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2015		Sep 30 2015

Total production (mboe/d)

Oil Sands	413.6	590.6	620.4		617.5		213.1		565.8		470.6		458.4

Exploration and Production	125.5	134.5	118.1		110.6		117.6		125.6		112.3		107.7

	539.1	725.1	738.5		728.1		330.7		691.4		582.9		566.1

Revenues and other income

Operating revenues, net of royalties	7 247	7 818	7 840		7 409		5 914		5 644		6 499		7 485

Other income (loss)	16	25	301		(15	)	(58	)	(67	)	94		72

	7 263	7 843	8 141		7 394		5 856		5 577		6 593		7 557

Net earnings (loss)	435	1 352	531		392		(735	)	257		(2 007	)	(376	)

per common share – basic (dollars)	0.26	0.81	0.32		0.24		(0.46	)	0.17		(1.38	)	(0.26	)

per common share – diluted (dollars)	0.26	0.81	0.32		0.24		(0.46	)	0.17		(1.38	)	(0.26	)

Operating earnings (loss)⁽¹⁾	199	812	636		346		(565	)	(500	)	(26	)	410

per common share – basic⁽¹⁾ (dollars)	0.12	0.49	0.38		0.21		(0.36	)	(0.33	)	(0.02	)	0.28

Funds from operations⁽¹⁾	1 627	2 024	2 365		2 025		916		682		1 294		1 882

per common share – basic⁽¹⁾ (dollars)	0.98	1.21	1.42		1.22		0.58		0.45		0.90		1.30

Cash flow provided by operating activities	1 671	1 628	2 791		1 979		862		48		1 443		2 771

per common share – basic (dollars)	1.00	0.98	1.68		1.19		0.54		0.03		1.00		1.92

ROCE⁽¹⁾ (%) for the twelve months ended	6.2	4.4	0.5		(4.6	)	(4.9	)	(2.2	)	0.6		5.1

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	278	103	(222	)	(112	)	(27	)	885		(382	)	(786	)

Common share information (dollars)

Dividend per common share	0.32	0.32	0.29		0.29		0.29		0.29		0.29		0.29

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	37.89	40.83	43.90		36.42		35.84		36.17		35.72		35.69

New York Stock Exchange (US$)	29.20	30.75	32.69		27.78		27.73		27.81		25.80		26.72

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A. ROCE excludes capitalized costs related to major projects in progress.


Three months ended (average for the period ended, except as noted)		Jun 30 2017	Mar 31 2017	Dec 31 2016	Sep 30 2016	Jun 30 2016	Mar 31 2016	Dec 31 2015	Sep 30 2015

WTI crude oil at Cushing	US$/bbl	48.30	51.85	49.35	44.95	45.60	33.50	42.15	46.45

Dated Brent crude	US$/bbl	49.85	53.75	49.50	45.85	45.60	33.90	43.70	50.30

Dated Brent/Maya FOB price differential	US$/bbl	5.80	9.05	6.70	6.80	7.65	8.95	10.35	8.50

MSW at Edmonton	Cdn$/bbl	62.30	64.25	62.00	55.10	55.80	34.50	53.55	56.55

WCS at Hardisty	US$/bbl	37.20	37.30	35.00	31.45	32.30	19.30	27.70	33.25

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	11.10	14.55	14.35	13.50	13.30	14.25	14.50	13.20

Condensate at Edmonton	US$/bbl	48.45	52.20	48.35	43.05	44.10	34.45	41.65	44.20

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.80	2.70	3.10	2.30	1.40	1.85	2.45	2.90

Alberta Power Pool Price	Cdn$/MWh	19.30	22.40	21.95	17.90	14.90	18.10	21.20	26.05

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	16.35	12.55	14.35	14.00	16.10	11.75	13.60	22.25

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	14.40	11.15	10.55	14.15	16.65	9.10	13.90	23.95

Portland 3-2-1 crack⁽¹⁾	US$/bbl	21.25	18.45	14.95	18.75	19.30	13.00	17.90	28.75

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	16.80	14.00	13.15	14.50	14.85	11.05	11.05	21.55

Exchange rate	US$/Cdn$	0.74	0.76	0.75	0.77	0.78	0.73	0.75	0.76

Exchange rate (end of period)	US$/Cdn$	0.77	0.75	0.74	0.76	0.77	0.77	0.72	0.75

(1): 3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

In addition to the impacts of changes in production volumes and business environment, net earnings over the last eight quarters were affected by the following events or one-time adjustments:

Suncor's significant accounting policies and a summary of recently announced accounting standards are described in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2016 annual MD&A.

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of contingencies. These estimates and assumptions are subject to change based on experience and new information. Critical accounting estimates are those that require management to make assumptions about matters that are highly uncertain at the time the estimate is made. Critical accounting estimates are also those estimates which, where a different estimate could have been used or where changes in the estimate that are reasonably likely to occur, would have a material impact on the company's financial condition, changes in financial condition or financial performance. Critical accounting estimates and judgments are reviewed annually by the Audit Committee of the Board of Directors. A detailed description of Suncor's critical accounting estimates is provided in note 4 to the audited Consolidated Financial Statements for the year ended December 31, 2016 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2016 annual MD&A.

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates, and to optimize the company's position with respect to interest payments. The company also uses physical and financial energy derivatives to earn trading profits. For more information on Suncor's financial instruments and the related financial risk factors, see note 28 of the audited Consolidated Financial Statements for the year ended December 31, 2016, note 13 to the unaudited interim Consolidated Financial Statements for the three months ended June 30, 2017, and the Financial Condition and Liquidity section of Suncor's 2016 annual MD&A.

In the fourth quarter of 2016, the Government of Quebec enacted a decrease in the corporate income tax rate from 11.9% to 11.5% evenly over the next four years, effective January 1, 2017. As a result, the company revalued its deferred income tax balances, resulting in a deferred income tax recovery of $10 million.

In the third quarter of 2016, the U.K. government enacted a decrease in the supplementary charge rate on oil and gas profits in the North Sea that reduced the statutory tax rate on Suncor's earnings in the U.K. from 50% to 40%. The company revalued its deferred income tax balances, resulting in a one-time decrease to deferred income taxes of $180 million in the E&P segment.

Based on their evaluation as at June 30, 2017, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at June 30, 2017, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three- and six-month periods ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Suncor has updated its previously issued 2017 corporate guidance, as set forth in Suncor's press release dated July 26, 2017, which is also available on www.sedar.com.

Certain financial measures in this MD&A – namely operating earnings (loss), ROCE, funds from (used in) operations, discretionary free cash flow, Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense and LIFO – are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze business performance, leverage and liquidity. These non-GAAP financial measures do not have any standardized meaning and, therefore, are unlikely to be comparable to similar measures presented by other companies. Therefore, these non-GAAP financial measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Except as otherwise indicated, these non-GAAP financial measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

Operating earnings (loss) is a non-GAAP financial measure that adjusts net earnings (loss) for significant items that are not indicative of operating performance. Management uses operating earnings (loss) to evaluate operating performance because management believes it provides better comparability between periods. Operating earnings (loss) are reconciled to net earnings (loss) in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A.

Throughout this MD&A, the company presents charts that illustrate the change in operating earnings from the comparative period through key variance factors. These factors are analyzed in the Operating Earnings narratives following the bridge analyses in particular sections of this MD&A. These bridge analyses are presented because management uses this presentation to evaluate performance.

ROCE is a non-GAAP financial measure that management uses to analyze operating performance and the efficiency of Suncor's capital allocation process. Average capital employed is calculated as a twelve-month average of the capital employed balance at the beginning of the twelve-month period and the month-end capital employed balances throughout the remainder of the twelve-month period. Figures for capital employed at the beginning and end of the twelve-month period are presented to show the changes in the components of the calculation over the twelve-month period.

The company presents two ROCE calculations – one including and one excluding the impacts on capital employed of major projects in progress. Major projects in progress includes accumulated capital expenditures and capitalized interest for significant projects still under construction or in the process of being commissioned, and acquired assets that are still being evaluated. Management uses ROCE excluding the impacts of major projects in progress on capital employed to assess performance of operating assets.


For the twelve months ended June 30 ($ millions, except as noted)		2017		2016

Adjustments to net earnings

Net earnings (loss)		2 710		(2 861	)

Add after-tax amounts for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(47	)	311

Net interest expense		221		317

	A	2 884		(2 233	)

Capital employed – beginning of twelve-month period

Net debt		14 545		9 234

Shareholders' equity		44 453		41 615

		58 998		50 849

Capital employed – end of twelve-month period

Net debt		13 780		14 545

Shareholders' equity		44 887		44 453

		58 667		58 998

Average capital employed	B	58 803		54 174

ROCE – including major projects in progress (%)	A/B	4.9		(4.1	)

Average capitalized costs related to major projects in progress	C	11 984		8 611

ROCE – excluding major projects in progress (%)	A/(B–C)	6.2		(4.9	)

Funds from (used in) operations is a non-GAAP financial measure that adjusts a GAAP measure – cash flow provided by (used in) operating activities – for changes in non-cash working capital, which management uses to analyze operating performance and liquidity. Changes to non-cash working capital can include, among other factors, the timing of offshore feedstock purchases and payments for commodity and income taxes, and the timing of cash flows related to accounts receivable and accounts payable, which management believes reduces comparability between periods.

Funds from (used in) operations in this MD&A for the twelve-month ended periods are the sum of the funds from (used in) operations for the particular quarter ended June 30 and each of the three preceding quarters. Funds from (used in) operations for each quarter are separately defined and reconciled to the consolidated GAAP measure in the Non-GAAP Financial Measures Advisory section of each respective MD&A for the applicable quarter.


Three months ended June 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Net (loss) earnings	(277	)	(1 063	)	182		26		346		689		184		(387	)	435		(735	)

Adjustments for:

Depreciation, depletion, amortization and impairment	927		938		289		461		168		172		26		34		1 410		1 605

Deferred income taxes	(73	)	(90	)	(38	)	(191	)	(4	)	32		103		9		(12	)	(240	)

Accretion	49		56		11		15		1		2		—		—		61		73

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(295	)	29		(295	)	29

Change in fair value of financial instruments and trading inventory	(1	)	1		—		—		(3	)	(11	)	61		140		57		130

Gain on disposal of assets	—		(32	)	—		—		(2	)	(1	)	—		—		(2	)	(33	)

Loss on debt extinguishment	—		—		—		—		—		—		25		99		25		99

Share-based compensation	8		15		—		—		4		9		14		13		26		37

Exploration	—		—		—		—		—		—		—		—		—		—

Settlement of decommissioning and restoration liabilities	(62	)	(31	)	(2	)	—		(5	)	(6	)	—		1		(69	)	(36	)

Other	2		4		(4	)	(9	)	(1	)	(1	)	(6	)	(7	)	(9	)	(13	)

Funds from (used in) operations	573		(202	)	438		302		504		885		112		(69	)	1 627		916

Decrease (increase) in non-cash working capital	469		198		270		156		1		234		(696	)	(642	)	44		(54	)

Cash flow provided by (used in) operating activities	1 042		(4	)	708		458		505		1 119		(584	)	(711	)	1 671		862


Six months ended June 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Net earnings (loss)	25		(1 587	)	354		(8	)	1 175		930		233		187		1 787		(478	)

Adjustments for:

Depreciation, depletion, amortization and impairment	1 868		1 855		573		817		328		342		63		63		2 832		3 077

Deferred income taxes	(64	)	(126	)	(97	)	(264	)	(13	)	23		150		62		(24	)	(305	)

Accretion	98		101		21		32		3		4		—		—		122		137

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(404	)	(892	)	(404	)	(892	)

Change in fair value of financial instruments and trading inventory	(8	)	13		—		—		(13	)	23		88		234		67		270

Gain on disposal of assets	(1	)	(33	)	—		—		(351	)	(1	)	(70	)	—		(422	)	(34	)

Loss on debt extinguishment	—		—		—		—		—		—		25		99		25		99

Share-based compensation	(78	)	(36	)	(3	)	2		(34	)	(22	)	(109	)	(70	)	(224	)	(126	)

Exploration	—		—		41		—		—		—		—		—		41		—

Settlement of decommissioning and restoration liabilities	(180	)	(150	)	(3	)	—		(6	)	(8	)	—		—		(189	)	(158	)

Other	22		24		33		(16	)	(10	)	(2	)	(5	)	2		40		8

Funds from (used in) operations	1 682		61		919		563		1 079		1 289		(29	)	(315	)	3 651		1 598

Decrease (increase) in non-cash working capital	918		(98	)	158		(40	)	(100	)	200		(1 328	)	(750	)	(352	)	(688	)

Cash flow provided by (used in) operating activities	2 600		(37	)	1 077		523		979		1 489		(1 357	)	(1 065	)	3 299		910

Discretionary free cash flow is a non-GAAP financial measure that is calculated by taking funds from operations and subtracting sustaining capital, inclusive of associated capitalized interest, and dividends. Discretionary free cash flow reflects cash available for increasing distributions to shareholders and to fund growth investments. Management uses discretionary free cash flow to measure the capacity of the company to increase returns to shareholders and grow the business.

Oil Sands operations and Syncrude cash operating costs are non-GAAP financial measures. Oil Sands operations cash operating costs are calculated by adjusting Oil Sands segment OS&G expense (a GAAP measure based on sales volumes) for i) costs pertaining to Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, research and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues

associated with excess capacity, including excess power generated and sold that is recorded in operating revenue; iv) project start-up costs; and v) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes. Syncrude cash operating costs are calculated by adjusting Syncrude OS&G for non-production costs that management believes do not relate to the production performance of Syncrude operations, including, but not limited to, share-based compensation, research and project start-up costs. Oil Sands operations and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this MD&A. Management uses Oil Sands operations and Syncrude cash operating costs to measure Oil Sands operating performance.

Refining margin and refining operating expense are non-GAAP financial measures. Refining margin is calculated by adjusting R&M segment operating revenue, other income and purchases of crude oil and products (GAAP measures) for non-refining margin pertaining to the company's supply, marketing and ethanol businesses, and the company's former lubricants business. Refinery operating expense is calculated by adjusting R&M segment OS&G for i) non-refining costs pertaining to the company's supply, marketing and ethanol businesses, and the company's former lubricants business; and ii) non-refining costs that management believes do not relate to the production of refined products, including, but not limited to, share-based compensation and enterprise shared service allocations. Management uses refining margin and refining operating expense to measure operating performance on a production barrel basis.


	Three months ended June 30				Six months ended June 30
($ millions, except as noted)	2017		2016		2017		2016

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 160		1 721		2 561		2 856

Other income	19		2		38		13

Non-refining margin	(375	)	(884	)	(870	)	(1 239	)

Refining margin	804		839		1 729		1 630

Refinery production⁽¹⁾ (mbbls)	42 629		38 754		84 169		80 169

Refining margin ($/bbl)	18.85		21.65		20.55		20.35

Refining operating expense reconciliation

Operating, selling and general expense	464		526		981		1 068

Non-refining costs	(249	)	(317	)	(537	)	(649	)

Refining operating expense	215		209		444		419

Refinery production⁽¹⁾ (mbbls)	42 629		38 754		84 169		80 169

Refining operating expense ($/bbl)	5.05		5.40		5.25		5.25

(1): Refinery production is the output of the refining process, and differs from crude oil processed as a result of volumetric adjustments for non-crude feedstock, volumetric gain associated with the refining process, and changes in unfinished product inventories.

Impact of First-in, First-out Inventory Valuation on Refining and Marketing Net Earnings

GAAP requires the use of a FIFO inventory valuation methodology. For Suncor, this results in a disconnect between the sales prices for refined products, which reflect current market conditions, and the amount recorded as the cost of sale for the related refinery feedstock, which reflects market conditions at the time the feedstock was purchased. This lag between purchase and sale can be anywhere from several weeks to several months, and is influenced by the time to receive crude after purchase (which can be several weeks for foreign offshore crude purchases), regional crude inventory levels, the completion of refining processes, transportation time to distribution channels, and regional refined product inventory levels.

Suncor prepares and presents an estimate of the impact of using a FIFO inventory valuation methodology compared to a LIFO methodology, because management uses the information to analyze operating performance and compare itself against refining peers that are permitted to use LIFO inventory valuation under United States GAAP (U.S. GAAP).

The company's estimate is not derived from a standardized calculation and, therefore, may not be directly comparable to similar measures presented by other companies, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP or U.S. GAAP.


Measurement		Places and Currencies
bbl	barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
boe/d	barrels of oil equivalent per day
mboe	thousands of barrels of oil equivalent
mboe/d	thousands of barrels of oil equivalent per day	Financial and Business Environment
		Q2	Three months ended June 30
GJ	Gigajoule	DD&A	Depreciation, depletion and amortization
		WTI	West Texas Intermediate
mcf	thousands of cubic feet of natural gas	WCS	Western Canadian Select
mcfe	thousands of cubic feet of natural gas equivalent	SCO	Synthetic crude oil
mmcf	millions of cubic feet of natural gas	MSW	Mixed Sweet Blend
mmcf/d	millions of cubic feet of natural gas per day	NYMEX	New York Mercantile Exchange
mmcfe	millions of cubic feet of natural gas equivalent	YTD	Year to date
mmcfe/d	millions of cubic feet of natural gas equivalent
	per day
MW	megawatts
MWh	megawatts per hour

The document contains certain forward-looking information and forward-looking statements (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements and other information are based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor's experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves and resources estimates; commodity prices and interest and foreign exchange rates; the performance of assets and equipment; capital efficiencies and cost-savings; applicable laws and government policies, including royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; the satisfaction by third parties of their obligations to Suncor; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and other information that address expectations or projections about the future, and other statements and information about Suncor's strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may", "future", "potential", "opportunity", "would" and similar expressions. Forward-looking statements in the document include references to:

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them. The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, E&P, and R&M, may be affected by a number of factors.

Factors that affect our Oil Sands segment include, but are not limited to, volatility in the prices for crude oil and other production, and the related impacts of fluctuating light/heavy and sweet/sour crude oil differentials; changes in the demand for refinery feedstock and diesel fuel, including the possibility that refiners that process our proprietary production will be closed, experience equipment failure or other accidents; our ability to operate our Oil Sands facilities reliably in order to meet production targets; the output of newly commissioned facilities, the performance of which may be difficult to predict during initial operations; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; our dependence on pipeline capacity and other logistical constraints, which may affect our ability to distribute our products to market; our ability to finance Oil Sands growth and sustaining capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; our ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta's Wood Buffalo region and the surrounding area (including housing, roads and schools); risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; changes to royalty and tax legislation and related agreements that could impact our business; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and changes to environmental regulations or legislation.

Factors that affect our E&P segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs, resulting in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor's foreign operations, including the unpredictability of operating in Libya due to ongoing political unrest and that operations in Syria continue to

be impacted by sanctions and political unrest; risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.

Factors that affect our R&M segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of, or changes to, taxes, fees, royalties, duties and other government-imposed compliance costs; changes in environmental and other regulations and policies; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of unexpected events such as fires (including forest fires), equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information technology and infrastructure by computer hackers or cyberterrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor's reserves, resources and future production estimates; market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws, including climate change laws; risks and uncertainties associated with closing a transaction for the purchase or sale of a business, asset, or oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor's control; risks associated with land claims and Aboriginal consultation requirements; risks relating to litigation; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

Many of these risk factors and other assumptions related to Suncor's forward-looking statements are discussed in further detail throughout this MD&A, and in the company's 2016 annual MD&A, 2016 AIF and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

The forward-looking statements contained in this MD&A are made as of the date of this MD&A. Except as required by applicable securities laws, we assume no obligation to update publicly or otherwise revise any forward-looking statements or the foregoing risks and assumptions affecting such forward-looking statements, whether as a result of new information, future events or otherwise.


(thousands)		June 30 2017

Common shares		1 662 876

Common share options – exercisable		21 084

Common share options – non-exercisable		35 432


1.	Advisories	5
2.	Second Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	25
6.	Financial Condition and Liquidity	27
7.	Quarterly Financial Data	31
8.	Other Items	33
9.	Non-GAAP Financial Measures Advisory	34
10.	Common Abbreviations	39
11.	Forward-Looking Information	40